Drilling fluids used in the drilling of subterranean oil and gas wells as well as other drilling fluid applications and drilling procedures are known. In rotary drilling there are a variety of functions and characteristics that are expected of drilling fluids, also known as drilling muds, or simply “muds”. The drilling fluid is expected to carry cuttings up from beneath the bit, transport them up the annulus, and allow their separation at the surface while at the same time the rotary bit is cooled and cleaned. A drilling mud is also intended to reduce friction between the drill string and the sides of the hole while maintaining the stability of uncased sections of the borehole. The drilling fluid is formulated to prevent unwanted influxes of drilling fluid filtrate and drill solids into permeable rocks penetrated and also often to form a thin, low permeability filter cake which temporarily seals pores, other openings and formations penetrated by the bit. The drilling fluid may also be used to collect and interpret information available from drill cuttings, cores and electrical logs. It will be appreciated that within the scope of the claimed invention herein, the term “drilling fluid” also encompasses “drill-in fluids” and “completion fluids”.
Drilling fluids are typically classified according to their base fluid. In water-based muds, solid particles are suspended in water or brine. Oil can be emulsified in the water. Nonetheless, the water is the continuous phase. Oil-based muds are the opposite or inverse. Solid particles are suspended in oil, and water or brine is emulsified in the oil and therefore the oil is the continuous phase. Oil-based muds that are water-in-oil emulsions are also called invert emulsions. Brine-based drilling fluids, of course are a water-based mud in which the aqueous component is brine.
Horizontal wells drilled and completed in unconsolidated sand reservoirs have become feasible due to improvements in technology and completion methods. Wells of this type require sand control, for example such as long open hole gravel packs or the installation of mechanical sand exclusion devices (slotted liners, pre-packed and expandable sand screens, etc.). Successful wells have been completed with horizontal, producing intervals as long as 5,000 ft. (1224 m) using these methods of sand control.
Usually the wells are drilled with conventional drilling muds to the top of the pay zone and the casing is set. The cement is then drilled out to the casing shoe and the shoe is tested. The drilling mud is then displaced with a “low damage potential drilling mud” generally consisting of polymers or other thickening agents, viscosity enhancers and insoluble particles for building a filter cake to bridge the pores in the sandstone reservoir. The particles are usually graded salt (NaCl) in saturated brine or graded calcium carbonate (CaCO3) in any fluid, and as technology has improved, the particle size distribution as compared with the pore throat openings of the reservoir has become more important. Sodium chloride and calcium carbonate are used because they are soluble in undersaturated brines or inorganic and/or organic acids, respectively.
Matching the particle size distribution (PSD) of bridging agents in drill-in fluids to the pore size openings of sandstone reservoirs being drilled is important for achieving spurt loss control and minimizing permeability reduction in the reservoir from undesirable fluid and particulate invasion. This matching is fairly straightforward in preparing the initial drill-in fluid and can be verified by, for example, laser light scattering prior to drilling since the bridging agent is typically the only particulate solid present. Once drilling begins, however, the drill-in fluid becomes contaminated with drill solids (cuttings) and other particulate components such as weighting agents and laser light scattering will only give the PSD of all the suspended solids—drill solids, weighting agents, and the bridging agent. It is important to distinguish between the solids to determine what percentage of the solids in any size range are capable of actually being removed from the pore throats of the formation by undersaturated brine or acid after drilling. It is also important to determine what size of bridging particle should be added to the drilling fluid to make up for what is consumed or degraded in the drilling process.
It would be desirable if methods could be devised to determine how much of a bridging agent only is present in a fluid, such as in a recirculated drilling mud, as distinct from other solids that may be present.